The Fayetteville Shale Peaks

While no one can ever be sure a petroleum producing area has reached its peak production until months or even years after the peak has occurred, there is strong evidence that the Fayetteville shale play has reached peak production. Based on information made available by the play’s leader, Southwestern Energy, and the Arkansas Oil and Gas Commission, it appears that the meteoric production growth from America’s third largest shale play is a thing of the past. More importantly, since the Fayetteville shale of central Arkansas was one of the only areas with production growth last year, its peaking will undoubtedly result in a tightening of the North American natural gas market. Due to the tremendous amount of Fayetteville shale data the Arkansas Oil and Gas Commission has put on its website, I have been able to do some detailed analysis on estimated ultimate recoveries and will share my findings with you. As always, I will discuss how my analysis of the Fayetteville relates to my outlook for Southwestern Energy (NYSE: SWN) and shale-focused Model Portfolio members.

The Fayetteville shale play is a layer of dense organic, gas-rich rock that lies approximately 7,000 feet below the surface in the core area of the play. The play was first discovered by geologists from Southwestern Energy in 2002 while drilling in a sandstone formation that was unexpectedly productive. This discovery became known to the company as the “Weddington Incongruity” and is marked on the map below. The technical staff at SWN eventually determined much of the excess gas production from the sandstone reservoir had migrated up from the Fayetteville shale directly below. Given the many geological similarities between the Barnett shale of the Ft. Worth Basin and the Fayetteville, SWN snapped up 343,000 net acres for $11 million in 2003. The below graphic clearly displays the position of both the Barnett and Fayetteville shales along the Ouachita Thrust belt:

Source: University of Arkansas

Though the Fayetteville has been producing for over six years, there are still a couple of important misconceptions about the play. As I discussed in past issues, possibly the biggest misconception about shale plays is that all of the acres in a play will be productive. Most energy observers underestimate importance of a trap system needed to create the required pressure and geological setting for shale gas production. For example, the Ouachita Thrust belt, which is part of a complex geological trap in Fort Worth, runs between the cities of Fort Worth and Dallas. Though the Barnett shale lies directly underneath both cities, Fort Worth has a trap system and substantial production from the Barnett, while Dallas has none. A similar situation exists in the Fayetteville shale. The Fayetteville shale exists throughout a large swath of land in the northern half of Arkansas but only a relatively small percentage of the land is productive. With 3,110 wells drilled in the play to date, a distinct core area has developed in the play in northern Conway and southern Van Buren Counties (Source: Arkansas Oil and Gas Commission). A secondary core area has developed in White County. Below is a graphical depiction of the drilling to date in the Fayetteville:

Source: Southwestern Energy

While production from the Fayetteville exists outside of the core area, wells on average become less and less productive the further they are drilled outside of the core area.

Another significant misconception surrounding the Fayetteville is the size of the expected ultimate recovery (EUR) per well. On its Q2 2011 earnings conference call, Chesapeake Energy’s (NYSE:CHK) CEO Aubrey McClendon announced that it had moved up its EUR per Fayetteville well from 2.4 billion cubic feet (bcf) to 2.6 bcf. (Chesapeake is in the process of selling its Fayetteville assets to BHP Billiton for $4.5 billion.) To put into perspective how ridiculous CHK’s claim of 2.6 bcf is, consider the following: Of the company’s 742 operated wells completed in the Fayetteville shale over the past five years, only 66 (9 percent) have produced more than 1 bcf and none have produced more than 1.7 bcf. CHK’s average Fayetteville well has produced only 541 million cubic feet (mmcf). On its Q4 2010 earnings conference call, Southwestern Energy upped its EUR for its proven undeveloped drilling locations from 2.2 bcf per well at the end of 2009 to 2.4 bcf per well at the end of 2010. The third largest operator in the Fayetteville, Petrohawk Energy (NYSE:HK), which recently sold its Fayetteville acreage to ExxonMobil for $650 million, has not publicly disclosed its EUR for the Fayetteville for some time, likely due to the poor performance of its wells. However, given that it locked in a huge loss in its sale of Fayetteville assets, I expect HK’s Fayetteville shale well EUR to be far lower then either of its two competitors. (More on HK’s sale later.) Based on information I found on the Arkansas Oil and Gas Commission’s website on 4/11/2011, there is strong evidence to suggest that CHK and SWN are overstating their EURs per Fayetteville well. Here are some of the highlights of my data mining efforts:

Only 11 wells of the 3,110 wells drilled into the Fayetteville since 2005 have produced more than 2 bcf. In other words, slightly more than a third of one percent of all wells to date have produced more than 2 bcf.

79 wells (2.5 percent) have produced more than 1.5 bcf

1,552 wells (49.9 percent) have produced less than 500 mmcf of gas.

Since completion technology has changed since 2005, when the start of large-scale development of the Fayetteville began, I believe it would be quite helpful to review the performance of the Fayetteville wells by year of first production:

Year of 1st Production

Number of Wells*

Cumulative Average Production per Well

2005

48

150 mmcf

2006

115

591 mmcf

2007

431

626 mmcf

2008

702

726 mmcf

2009

848

674 mmcf

2010

875

363 mmcf

2011

68

NM

Source: Arkansas Oil and Gas Commission

*16 wells before 2005 were excluded from above table

Before analyzing the above data table, I have to commend the Arkansas Oil and Gas Commission (AOGC) for making the above information available to the public. Unlike other states that fail to provide any production information or data that is months or years old, the AOGC provides outstanding granularity in the information on one of the most important natural gas fields in the country.

So what is this table telling us about EURs in the Fayetteville shale? First, based on the above information, there is little doubt that CHK and SWN have grossly overstated their EUR per well. For example, the 594 wells drilled between 2005 and 2007 are unlikely to ever produce much more than 1 bcf each. While I do not have access to the actual decline curves for these wells, there is no doubt that Fayetteville operators are using unrealistic decline curves that include transient flow (the gush of gas occurring immediately after a well is put on production which should not be included in proper analysis) and b-factors that are unrealistically high. For more information on b-factor please see Issue 20 which was published on December 1, 2010.

To further distort projected EURs, operators in the Fayetteville are using unrealistic terminal decline curves that extend the life of wells out past 50 years. Based on data that is now coming out of the Barnett, there is simply no evidence to support the hypothesis that a shale well will have a productive life of 50 or more years. An estimated one quarter of the wells that were put into production in the Barnett five years ago have gone dry. Without the reserves booked into years 10 through 65, which have almost no present value, CHK and other operators would not be able to justify Fayetteville EURs they have been advertising.

The increased performance of wells drilled in 2008 and 2009 are likely to have EURs higher than wells of the previous years since the largest operator in the play, Southwestern Energy, greatly increased its lateral well length and the number of fracture stages per well. According to a recent presentation on the company’s website, SWN increased the average Fayetteville lateral from 3,301 feet in Q1 2008 to 3,874 feet in Q1 2009 (17% increase) and to 4,348 feet in Q1 2010 (32% increase over Q1 2008). Such a large increase in average lateral well length will certainly increase recoveries in the early years but may not lead increased ultimate recoveries since longer laterals have greater potential to die early deaths due to water incursion. While it is still too early to draw many conclusions about EURs for 2008 and 2009 wells, a reasonable case can be made for EURs of 1.3 bcf for these wells, but more data will be needed.

In addition to lower EURs per well than what is currently estimated by participants in the play, the EUR for the entire Fayetteville shale play is likely far smaller than is widely believed. Looking back at a presentation that was given by SWN in November 2008, we are provided with another example of the shrinkage of a shale play down into relatively small core area. As you can see from the adjacent graphic, in the fall of 2008, SWN was conducting three pilot programs in Franklin County, one in Johnson County and three more pilots in Pope County.

Now that we have more than two years of data from the AOGC, we can draw some conclusions as to the prospectivity of these three counties. In Franklin County, 17 wells were drilled and the best well to date, put into production in April 2005, has produced only 137 mmcf. Only two wells were drilled in SWN’s Johnson County pilot program and the best well, drilled in October 2007, has produced only 39 mmcf to date. In Pope County, 35 wells have been drilled to date with the best well in the County having produced 659 mmcf since going into production in August 2008. The average well in Pope County has produced only 235 mmcf.

Given the weak results from these three counties so far, there is a strong likelihood that the majority of these three counties are not prospective for production from the Fayetteville shale. Therefore, excluding Franklin, Johnson and Pope counties from future development, the total number of acres that are likely to produce from the Fayetteville is approximately 750,000 acres. Assuming 160 acre well spacing on 750,000 acres of prospective Fayetteville, a reasonable assumption since a portion of the play will not be drillable due to naturally occurring faults or surface issues, the Fayetteville shale play can be expected to host approximately 4,700 drilling locations. With over 3,100 drilling locations already into production, more than half of the prospective acreage of the Fayetteville has already been drilled.More importantly, even if we make the aggressive assumptions that each Fayetteville well will produce 1.3 bcf and there are 7,500 locations (100 acre spacing), the EUR for the entire play is 9.75 trillion cubic feet.[Note: If the Fayetteville, America’s third largest shale play, is only 10 tcf, an enormous field by nearly every metric, it would be extremely difficult to see how we have a 100 year supply of natural gas or approximately 2,500 tcf of recoverable gas.]

I expect 2010 to be the year of peak production in the Fayetteville for two very simple reasons. First, substantially fewer wells are likely to be drilled in 2011 than in any of the three previous years and the play’s high well decline rates will result in a fall off in 2011 production. The management team of play leader SWN has repeatedly stated it will drill approximately 100 few wells in 2011 than it did in 2010. Prior to the Petrohawk’s sale of its Fayetteville assets, the company had dropped all of its operated rigs in the play. CHK had substantially reduced its operated rigs in the play over the past two years prior to the sale of its Fayetteville assets to BHP.

Second, and more importantly, it appears that each new well is intersecting progressively lesser quality rock. As you can see from the above table, over the past two years, SWN has been drilling longer and longer laterals with more fracture stimulations but is making less productive wells.

Comparing results from Q2 2009 and Q4 2010 it is clear that SWN’s average well lateral length increased but productivity declined. Consistently drilling longer laterals and getting less gas is a strong indication that production in the Fayetteville has reached a peak.

Source: Southwestern Energy

Though Fayetteville well recoveries are likely to be far lower than previously advertised, it does not mean that the play will be unprofitable for all operators. Similar to nearly every other shale play, the company that identifies the play early on and secures a meaningful land position before the land rush begins has vastly superior economics compared to latecomers. For example, Petrohawk Energy paid $785 million for only 60,000 acres in the Fayetteville in 2007 and 2008 in three separate transactions while SWN paid only $11 million for its initial 330,000 acres in 2003. By the end of 2005 SWN had invested $135 million in its Fayetteville project area, which included 860,000 net acres, and 88 wells in 15 different pilot programs. HK eventually acquired a total of approximately 150,000 net acres in the Fayetteville and is likely to have spent well over $1 billion on acreage alone. To build HK’s gathering system in the Fayetteville and drill its operated wells, the company invested an estimated $500 million. All told, Petrohawk easily spent $1.5 billion to acquire and develop its Fayetteville acreage. HK is likely to have received between $100 and $200 million in cash flow from its Fayetteville properties and exited the play with a sale to ExxonMobil for $650 million. In less than five years, HK destroyed approximately $700 million of shareholder capital in the Fayetteville. [It should be noted that HK was an early mover into the Haynesville and was able to establish a substantial beachhead in the play, which has allowed HK to drill many of the best wells in the Haynesville.] On the other hand, it appears that Southwestern’s low-cost early entry into the Fayetteville, which allowed them to tie-up the best acreage and control a huge portion of the gathering system, has created substantial shareholder value. When gas prices rise to respectable levels (to at least the low double-digits), which they will likely do later this year, SWN will have a dominant position in a highly profitable gas play. In the meantime, the company’s Fayetteville acreage will be largely break-even until gas prices go north of $5.00 per mcf.

The peaking of the Fayetteville shale is an important milestone for the North American natural gas market since it is now the third significant shale play to have peaked. The other two shale plays that have peaked are the Antrim shale in Michigan and the Barnett shale. Without production growth from the Fayetteville in 2011 to offset declining conventional onshore production, declining production in Canada and declining production in the Gulf of Mexico, natural gas demand will soon substantially outstrip supply and prices will skyrocket. All the pieces are in place for substantially higher natural gas prices, however Mr. Market will recognize the incredibly strong fundamentals of the natural gas market only when he is ready and not a second earlier.